National Fuel Gas Co (NFG) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter National Fuel Gas Company earnings conference call. My name is Madge and I will be your operator for today. At this time all participants are in a listen-only mode. We will conduct a question and answer session towards the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to Mr. Tim Silverstein, Director of Investor Relations. Please proceed, sir.

Thank you, Madge, and good morning everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Smith, Chief Executive Officer and Ron Tanski, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President.

At the end of the prepared remarks, we will open the discussion to questions. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, we will begin with Dave Smith.

Thanks, Tim, and good morning to everyone. Second quarter was another very good quarter for National Fuel. Earnings for the quarter were $80.4 million or $0.97 per share, which was right in line with our expectations. Compared to the prior year, second quarter earnings were up almost $7 million or $0.05 per share, primarily as a result of an over 40% increase in Seneca's earnings per share. Higher crude oil prices and a 68% increase in production in the East were the principal drivers. Much of that increase in production was a result of our Marcellus program, where we continue to build momentum.

Seneca's Marcellus production for the quarter, which totaled 1.3 Bcf accounted for over one-third of the East Division's natural gas production. And that's pretty impressive considering that this is only the second quarter of production from our Seneca-operated Marcellus program. Looking ahead to the coming quarters, we will continue to be aggressive in developing our Tioga County acreage.

We'll also continue to increase our activity in the Western Development Area with an eye towards characterizing, prioritizing, and de-risking our over 700,000 acreage position in that region of the Marcellus. As you know, most of the mineral rights on that acreage are held in mineral fee and thus carry no royalty, which greatly improves the returns we realize from production on that acreage. Given our success to date, particularly in Tioga and given the economic advantage of our fee acreage, despite weak natural gas prices, we're holding our 2010 Marcellus capital budget at $260 million to $280 million. Matt will provide more detail on Seneca's operations later in the call.

Before leaving the E&P segment, a brief comment on Seneca's California oil properties, and the advantages of some balance between oil and gas production. Oil production from California accounted for roughly one-third of Seneca's overall consolidated production for the quarter and given the relative strength of oil prices, provided a counterbalance to the decline in realized natural gas prices. These properties are a great source of cash to fund our Marcellus program. At current prices, we expect our West Division to generate approximately $100 million of free cash flow in fiscal 2010.

Turning to our Midstream business, NFG Midstream just completed construction of the second phase of its Covington Gathering System in Tioga County which extends that system further south to our acreage on Pennsylvania State Forest Tract 595. In addition, based on the success in the Tioga County Area by Seneca and by other producers, NFG Midstream is already looking to expand the overall capacity of the Covington system. By adding some modest facilities, we can increase the capacity from its current 100 million per day to about 200 million per day.

In the regulated Pipeline and Storage segment, we continue to make excellent progress on our multiple expansion opportunities. These projects are designed to move Marcellus production from infrastructure and market constrained Appalachia to the expanding markets in Canada or the Northeast, in some cases both. As we announced last week, Supply Corporation recently executed a binding precedent agreement with Statoil for 100% of the capacity on the Northern Access project.

Northern Access is designed to move 320 million per day of Marcellus production to Supply Corporation's interconnection with TransCanada which is at Niagara. Because it uses existing pipelines, the cost of this project is relatively modest. We anticipate spending approximately $60 million on 16,000-horsepower of additional compression, meter upgrades, and other minor enhancements that will make the system bi-directional. We expect the Northern Access project will go in service in mid-2012. Supply Corporation's Lamont and Line N projects are also proceeding according to plan.

Construction is well underway on the Lamont project which will add approximately 1200-horsepower of compression at Supply's interconnection with the Tennessee 300 line. This project, which will provide an additional 40 million per day of takeaway capacity, is expected to cost about $6 million and should go in service next month. Station engineering and environmental studies are underway for Supply's Line-N expansion, which is a $23 million pipeline and compression project at the southwestern end of our system that will move about 150 million per day of Range Marcellus production to an interconnection with Texas Eastern. Supply Corporation began the FERC pre-filing process last fall and expects to file its 7c application later this month.

Lastly, as we indicated in last week's release, Empire has executed a binding precedent agreement with East Resources for 200 million per day of firm transportation service on its Tioga extension project, which extends the connector portion of Empire system from Corning, New York down to Jackson Township in Tioga County, Pennsylvania. While that project will move forward on the East Resources commitment alone, further negotiations with another producer are close to a conclusion, and we're confident an additional 150 million per day of service will be committed to in the very near future. Preliminary routing and environmental work have been completed and engineering work is now underway.

We expect to file an application with FERC this summer and as a reminder, the estimated cost of the project is $45 million and the projected in-service date is September 2011. We're very excited about these expansion opportunities. For a relatively modest investment of about $134 million, these projects represent a significant and a strategic expansion of our system. In total, they'll add 860 million per day of capacity. Our current peak capacity on our Supply and Empire systems, that's about 40%, just to give you some perspective, and those projects will bring approximately $50 million of annual incremental revenue.

We're optimistic that those four projects are the first of many similar opportunities. The customers who have committed to these initial projects are some of the largest players in the region, including Seneca, Statoil, Range, East Resources and others. They've recognized the geographic advantage of our system and our expertise in building infrastructure in New York and in Pennsylvania. As drilling in the Marcellus ramps up, the need for new pipeline capacity will become even more critical. National Fuel stands ready, willing and able to meet those demands.

In closing, this was a great quarter for the Company because we continued to execute on our growth strategy, which, as you know, was focused on Appalachia. The current low natural gas price environment will be a challenge to producers, including Seneca. But I firmly believe that our balanced business model, much of which is not commodity price sensitive, our low cost structure in the Marcellus and our financial strength make National Fuel well positioned to thrive even during difficult times.

Thanks for listening today and I look forward to seeing many of you at the AGA later this month. With that, I'll turn the call over to Matt.

Thanks, Dave. Good morning, everyone. Seneca had another great quarter, with production up 17% versus last year's second quarter. West Division production was essentially flat, while the Gulf was up 8% and the East was up 68%.

The Gulf production increase is primarily due to new production this year from our Cyclops Field, which accounts for about 30% of our Gulf of Mexico production from only two wells. Given the performance to date, I expect that we will be revising our reserves for these two wells upward at year-end. In addition, last month we reached TD on a third Cyclops well, encountering approximately 140 feet of pay. This third well should be on line sometime this summer.

In California, we continue to keep production steady at about 9,000 barrels of oil equivalent per day. We have completed the drilling of 14 wells on the South Midway Sunset property that we acquired from Ivanhoe with good results. We plan to add steam generation capacity and have the new development wells up to about 400 barrels of oil per day by this time next year. Perhaps more importantly, one exploratory well was drilled far from the existing producers. This well found a thick pay section and will add another 15 to 20 potential well locations and 1 million barrels of potential reserves.

In the East, production continues to grow as we bring on additional Marcellus producers. In fact, we are now producing more gas from the Marcellus than we are from our 3,000 shallow Appalachian wells. Our Seneca-operated program in Tioga County has been particularly exciting and successful. Our best well flowed at almost 11 million cubic feet per day for 30 days and is still making 6.5 million after 110 days on line. I expect this well to make its first Bcf in June, less than six months after coming on line.

Our current production from six wells in the Tioga Covington area is now over 30 million cubic feet per day. To the south of our activity in the Covington area, we tested our first horizontal well in Tract 595, which we picked up at the 2008 DCNR state lease sale. This well had a one-week IP of over 7 million cubic feet per day, confirming our expectations for this 7,000-acre block. We now have the second phase of Covington Gathering System extended down to this acreage and we will bring in a rig for development drilling sometime in July.

Meanwhile, we continue to acquire additional acreage in Tioga, Lycoming and Potter Counties that is contiguous with our existing acreage blocks. We have a total of approximately 40,000-acres in these three counties and have laid out 270 horizontal well locations, which equates to over a Tcf of resource potential. By mid-summer, we will have three rigs dedicated to this area.

In addition to our activity in Tioga County and our joint venture activity with EOG, we've now fracked two wells on the far western portion of our acreage. The first well in western Elk County IP'd at nearly 4 million cubic feet per day and averaged 3.4 million over its first week. Last week we fracked our second western well, this one in McKean County.

The well had a relatively short lateral and a less effective frac than the previous well, but still IP'd at 1.5 million cubic feet per day. Over the course of the next months, we will have test rates for several additional wells in what we refer to as the Western Development Area, where we own the minerals and therefore have zero royalty and superior economics. By fiscal year-end, I expect that we will have significantly de-risked our western acreage and prioritized areas for development.

Last, month we added a third Seneca-operated horizontal rig. This rig is a triple that can crawl from well to well on a multi-well pad, allowing us to drill a quick sequence of top holes on air before we change over to mud and drill the laterals. Because we are going to a multi-well pad approach, our production growth will be stair-stepped, with our next anticipated increase, significant increase, being a seven-well group that should be fracked and on line late this summer.

In summary, Seneca's second quarter results and year-to-date results were excellent, production for the first six months of 2010 was 19% higher than for the first six months of 2009. This growth is primarily from the Marcellus Shale where we continue to have outstanding results. With three Seneca-operated rigs and one to two EOG operated rigs, we expect to drill 50 to 70 Marcellus wells this year and should exit our fiscal year at 40 to 70 million cubic feet per day and exceed 80 million cubic feet per day from the Marcellus by the end of the calendar year. With that, I'll turn it over to Ron.

Thanks, Matt. Good morning, everyone. Quarter-over-quarter, the increase in the earnings from the Exploration and Production segment more than offset the decline in the earnings in the Pipeline and Storage segment. While the earnings in the Utility and Energy Marketing segments remained pretty flat. The earnings release describes all of the drivers of the earnings changes, so I can be brief and we can get to your questions.

Following our standard practice for our earnings guidance, we've held our base commodity price inputs constant at $5 per MMBtu for gas and $75 per barrel for oil. We've updated our sensitivity table that reflects possible changes to the earnings guidance range as changes to commodity prices will effect revenues from our unhedged production over the remainder of the year. Using the mid-point of our production guidance, the table on page 22 of yesterday's release shows that we've got a little over 52% of production hedged for the remainder of the fiscal year at $74.58 per barrel of oil and $6.90 per Mcf on the gas side.

In the Utility segment, our Conservation Incentive Program and the revenue decoupling mechanism in our New York jurisdiction continue to operate as expected. For the 12 months ended March 2010, we estimate that residential, normalized customer usage in New York decreased by approximately 2.9% for the entire revenue class. That's in addition to the 3% decline that we saw over the same 12-month period last year.

In Pennsylvania, we saw normalized usage decrease by 5.8% over the same 12-month period where it only decreased by less than a percent over the same 12-month period last year. At average billing rates during the quarter, we calculated that the conservation by our New York residential and small commercial customers saved them almost $4.6 million during the quarter. Individual customers can also receive rebates of up to $400 for the installation of new equipment.

At the same time, our customers achieved that $4.6 million in savings, the Revenue Decoupling Mechanism preserved $475,000 of revenue at the Utility during the second quarter. From a consolidated level, even with the $236 million of capital expenditures during the first six months of the fiscal year, the equity component of our capitalization stands at 57% at the end of March, and we still have plenty of cash to fund the CapEx program for the remainder of the year and to buy and inject gas into storage for our utility customers for the upcoming 2010 and 2011 heating season. With that, operator, we're ready to open up the line for questions.

Thank you, sir. (Operator Instructions) And your first question comes from the line of Carl Kirst from BMO Capital. Please proceed.

Thanks. Good morning, everybody. Great work. Hey, Matt, just very quickly, understanding we're still in the science part aspect, but the two horizontal wells on the western acreage. Is there anything to lead you to believe that the actual development costs of that side is going to be any different than Tioga and the Eastern, or I'm just trying to get a better sense of the economics, is it just going to be essentially the geology and the rock, or will there be differences in well costs as well?

Well, Carl, it is a little more shallow, so that could have some impact on the cost, but it's not really that substantial. What I would focus on, though, is this is an area where we mostly own the minerals in fee, so we'll have no royalty here, which that does have a substantial impact on the economics.

No, absolutely understood, but just looking for relative comps between Tioga and -- okay. No, that's great. And then the second question really was more on the regulated side, the development projects, great to see you guys get the market share. The $50 million, Dave, of annual incremental revenue that's going to be coming from these projects. Are these negotiated rates where you might be getting a rather thicker return? Or when we actually take it down to an EBIT or net income, will that return on capital, the $134 million, be closer to the standard regulated rate of return?

Yes, these are really rolled in rates on our existing pipeline systems, and so -they are for the most part, they're at max rate and I think there's one below max, one discount off of max rate in there. But these are generally cost of service, returns, the -- ultimately be rolled into our rate case that will be filed in the future in the Pipeline and Storage sector.

Great. Appreciate the clarification.

And your next question comes from the line of Jonathan Lefebvre from Wells Fargo. Please proceed.

Good morning. It's Jonathan Lefebvre from Wells Fargo. Nice quarter. Wanted to follow up on the Western wells and just get a sense for -- EOG is out there saying -- talking about a little higher Bcf EUR per well. And was wondering -- you're still using a 3 Bcf EUR. What's the difference there and should we be thinking that potentially you come up to their numbers or are they being slightly more optimistic?

Jonathan, I guess the way I look at it is we see 3 Bcf as a good average for what we expect the EURs to be in the Western acreage outside of the Tioga, Lycoming, Potter area. I guess I'm not exactly certain what EOG has said about their EURs. We will certainly have wells that will -have, will produce a lot more than 3 Bcf, but I suspect that we'll have some that will be less than that as well and I would still say 3 Bcf is a pretty good average for that Elk, McKean area.

Okay. Thanks. And on that second well that you mentioned, it was -- the IP was slightly less than the first. Do you attribute that to differences in geology? Or is that more of a function of maybe not getting as long of a lateral as you would have liked? Or can you maybe --

Well, certainly the length of the lateral is a factor, but even corrected for lateral length as well as -- is a little weaker than the previous one. We're studying it. I guess my short answer would be that I think we'll find that different parts of the Marcellus need to be fracked differently than other parts. So that could be a factor and it could also be a localized geological effect,so a lot of study to be done there. I guess what I would say is, this is one well. We have other wells in both directions that tested over 3 million a day, not too far from this well. So it's not a -- it's just another data point.

Okay. Fair enough. And then just maybe turning to the Pipelines, nice expansion projects that you announced last week. I notice, though, on the open season that you had a pretty healthy interest, five times oversubscribed. Does that indicate that maybe a larger line is warranted at this point?

Oh, I think ultimately, in fact, part of the Tioga extension project will take gas to Canada as well. So, yes, I clearly think that the policies of the Canadian government where they've mandated conversion of coal-fire generation to gas has resulted in a much stronger price up in Canada, which is going to mean a lot of this Marcellus production is going to try to make its way to Canada. And I think, Jonathan, you're referring to -- I think we had like 1.6 Bcf of asks, so to speak, on that Northern Access project,so yes, we think Canada will be a good market and we're in a nice position to take advantage of it and that's why our projects are now going to turn, it's going to basically make our system bi-directional, to be able to come and go from Canada. So for us, that's a pretty big deal, strategically.

Fair enough. And then maybe if I can just ask a bigger picture question on the -- Dave or Matt, whoever wants to take this, just around joint ventures and accelerating the production, I guess. We've seen some of your peers take advantage of the appetite in the market. How do you think about that today for your acreage?

Well, I guess I'll start and then turn it over to Matt. We have looked at a joint venture, we've looked at a number of joint ventures, but in particular one we considered on a portion of our acreage. We decided not to pull the trigger at the end of the day, at least at this time, because really there was no compelling reason to do it. We're not capital constrained. We have the capital to do the projects that are on the drawing board. We don't have the pressure of expiring leases, I think a number of producers have that pressure. We don't have it. We don't need expert -- we're best in class, I think, in terms of our expertise. It's not to say that you don't do it and certainly we'll be considering it in the future, but at this point in time, we decided not to do it and, Matt, I'll, I guess, ask you to comment.

I guess the only thing I'd add to that, Jonathan, I believe we could get a decent price per acre over a large swath of our acreage if we did something today. But as we drill more wells, all we're going do is increase the value of that acreage. And, also, as industry matures, the Marcellus, I think you're going to see these types of joint ventures go for higher and higher dollars per acre, so there's just no reason to do it immediately. We'll continue to consider it as we move forward, but down the road, we may do a small joint venture on a portion of our acreage and we may do that a year from now, we may do it three years from now.

Great. I appreciate the color. Thanks, guys.

And your next question comes from the line of Becca Followill from Tudor, Pickering, and Holt. Please proceed.

Good morning, guys. Several questions for you. First, with the wins that you had on the pipeline projects, what do you look at -- has there been any change to your CapEx guidance for 2011? And is that funded from cash flow from operations or are you outspending in 2011?

Becca, this is Ron. In 2011, the Pipeline and Storage projects are obviously going outspend cash flow from that segment, and that spending isn't going to take us too far outside of the realm of the maturing debt and the rolling over of the $200 million issue that we have coming up in November. So it's -- yes, we are outspending cash flow, but it's certainly within our ability, based on the interest and the oversubscriptions we had on our issuance last spring.

So you don't see any need to issue equity to help fund those projects?

No.

No.

Okay. Great. And then on the $50 million of incremental revenues from the four projects that you talked about. Is there any offset, since you talked about in the press release some contracts expiring on some of the systems that imported in from Canada? Is there an offset to that as we flow the volumes back into Canada?

Yes. There's definitely -- I mean that's, in part, what causes the opportunity is some of the shippers bringing it in from Canada, no longer bringing it in from Canada and allowing us to turn the other direction. The incremental -- the drop in revenue, I don't have that number.

Yes, but Becca, like specifically for Northern Access, where we were moving gas back up to Canada, we still have -- I mean, we've designed that project to actually continue to flow gas in both directions. We still have contracts to move gas from Canada down off to Leidy, Ellisburg and Leidy. We still have the ability to meet those commitments, in addition in the operation of the system, to move gas the other way. So the decline that you've seen, that we've talked about this quarter in revenues, is -- well, we may see a couple of more contracts turn back, but not a whole bunch of an offset there.

Yes, Rebecca, we can get you the number. It's not a significant amount, but there is some offset there.

I just didn't want to go in and add the full $50 million in maybe there was -- I know it's not completely a wash, but if there was $5 million to $10 million of it that was contracts expiring and that frees you up the capacity to be able to export into Canada. Wanted to make sure I got the numbers right.

Yes, it's not nearly a wash. But we can get you that number.

Okay. Great. Thank you. And then finally, on the production side, with the Marcellus gas coming on in slugs and it sounds like it's going to be late summer before that next big slug comes on line. Should we look for the trajectory for the second half of the year in production? Is it going to be very much fourth quarter loaded? Or is the new well in the Gulf of Mexico, Cyclops, going to help bridge the gap there?

I wouldn't count on the Cyclops well having a real large impact, Becca.

Okay.

Partly because other wells are declining and, also, that timing is several months down the road, also. But what I would keep in mind is when you look at our second quarter production, you've got Marcellus gas that was coming on gradually during the second quarter. Well, where we are for the third quarter is going to be significantly higher than the second quarter because the rates we're at now, we've just gotten to that point.

In addition, we've got a little more EOG gas from the joint venture coming on. So you'll see a quarter-over-quarter -- sequential quarter-over-quarter increase from second to third quarter, and depending on the timing of that next big slug, as you said, you can see a substantial increase in the fourth quarter, it's just a question of exactly when that happens.

Great. Thank you, guys.

And your next question comes from the line of Andrea Sharkey from Gabelli. Please proceed.

Hi, good morning.

Good morning.

Good morning.

I just wanted to ask you, looking at maybe something -- like what Questar announced, that they're thinking about doing, they're going to separate their E&P business from utility. Is that something you guys may be considering in the future or do you see that there's a reason or a good strategic fit to have all your businesses stay -- keep them together?

Yes, well, I guess first -- and I'm glad you asked the question that way. I think in Questar's case, they're 75-80% E&P and we're about 50/50 regulated on one side and E&P on the other. So we like the way those companies fit together. We like the stability on the regulated side, we like the upside of the Marcellus. I guess we look at it right now as been having the best of both worlds. The regulated's aren't commodity price sensitive and then we have the Marcellus. And we're pretty comfortable with the way the assets fit. We're pretty comfortable with how the models performed over time, I think we've outperformed pretty much every sector, but as you move more and more toward an E&P company, which ultimately over time we certainly will be moving more and more toward an E&P company, you certainly have to consider it. I mean, we work for the shareholders, and as we develop more toward an E&P company, we'll certainly keep that consideration in the forefront of our minds.

Great, that makes sense. And then I was just wondering if you had any changes to your plans for developing the Marcellus? I think the last information was that you planned to do to 50 wells to 70 wells in 2010, 100 wells to 130 wells in 2011, if that's still a good number? And then maybe talk about the difference between the high and the low end of that range and if you think you might have to add any additional rigs to achieve that -- those plans?

Well, let me start with the last part of the question, yes, we will have to add rigs to achieve those plans and, actually, that's really the way to look at it. The timing of when we add rigs is what controls the high end and the low end of those ranges. We just added our third rig, third Seneca-operated rig. We plan to add a fourth rig in August, September time frame. But we may decide -- for whatever reason, we may decide to add that rig in October or November, and then a fifth rig would come on April time frame. So exactly when we bring those rigs on is what controls that well count.

Okay. Great. And then just maybe to follow up on that quickly and then I'll turn it back, are you seeing any changes in terms of pricing on rigs? Are companies trying to push through price increases? Are those costs going up and I guess maybe even on the fracking, the pressure pumping as well? Maybe you could talk about what you're seeing on the cost side.

Yes, on the rigs I guess what we're seeing is it's -- for the rigs we want, it's a pretty tight market. You might think with low gas prices that it would still be easy to get rigs at a good price, but it is fairly tight. I'm not so sure that it's substantially higher in cost as much as there's a little bit of lead time to get the rigs when you want them.

On the pressure pumping side, we are seeing an increase in cost. It's also not necessarily easy to get the frac crews scheduled for the precise dates you want. So that's a little tight as well. Overall, though, I would say that our learning and our ability to increase efficiency through pad drilling and more efficient water handling is going to allow us to reduce costs faster than they're going up from the service companies.

Okay. Great. That's very helpful. Thanks a lot.

(Operator Instructions) And your next question comes from the line of Ray Deacon from Pritchard Capital. Please proceed.

Yes, I had a question about the 7 million a day IP rate well you announced. Was that in Potter? Tioga? that area?

Yes, that was in Tioga County, Ray. It's on Tract 595.

Okay.

Which is one of the state forest tracts to the south of our Covington production.

Got it. Great.

Looks like high rates as well.

Yes, it seems very really high for that area, that's great. That Cyclops well, I was just curious, what was the formation and do see any other potential targets in California?

Cyclops is in the Gulf of Mexico.

I'm sorry.

It's Myocene.

Myocene. Got it. Great, never mind. I guess I might as well ask that question. It seems as though a lot of people are interested in whether you see shale potential on your acreage because you're right next to Oxy who's spent a lot of effort on it. Do you see yourselves drilling a horizontal well in California in the next year or so, I guess?

Yes, we've been drilling Monterey Shale wells in California for, I don't know, about five years, I think. That's been a big part of our development in Lost Hills. But those have been vertical wells. We've talked about the possibility of drilling a horizontal well there and that's still something that could happen. I guess the thing to keep in mind is our footprint in California is relatively small, so while those shale wells and particularly a horizontal well could add some incremental reserves and production, it would never be a terribly large impact on our production or reserves.

Got you. Got you. Great. And I guess just one for Ron, it seems like with the significant rig count in the Marcellus potentially going to 200 rigs by the end of next year, the flows of gas look like they're going to change significantly. And what are your long-term thoughts about how you might be able to capitalize on that and be able to participate in some of the bigger projects that end up happening?

Well, Ray, as you know, we have our West to East and Appalachian lateral projects that we're working to -- trying to get fully subscribed before we go out and actually start building those. But those are designed to go right through the heart of the Marcellus and get that production hooked up and into other major interstate pipelines. So, the more and more of that Marcellus gas comes on, the producers we expect will be a little bit quicker to be committing to those projects.

Got it. Great. Thank you.

And your next question comes from the line of Bob Meyer from Roosevelt Investment Group. Please proceed.

Good morning, everybody.

Hi, Bob.

Just two different kinds of questions. One on the corporate structure side that you've talked about. There have been a couple of recent monetizations of gas storage. I'm not that familiar with -- I know you have some storage capabilities and I don't know exactly how much is externally or internally used. But can we add that to the list of possible monetizations in the future? And then totally separate, at what point do you think you might be doing some testing of horizons other than the Marcellus and Pennsylvania?

Well , with respect to the storage, that's all FERC regulated within our Pipeline and Storage segment, about 40% of that is used for -- sold to both the Utility and our Marketing company. So if you want to look at it as being internal, that's , let's say, use in our service territory. And the rest is already committed under long-term commitments to marketers and utilities up and down the East coast. So we don't see any, let's say, monetization of that, We're just going to sit back and enjoy the continued cash flow stream from that and with respect to your second question, I'll turn that over

Yes. In Pennsylvania, of course, we drill upper Devonian and Sandstone targets regularly, we have for 70 years or 80 years. Now, with respect to other shales, we do have some prospectivity for at least one other shale, on some of our acreage. But for proprietary regions, I guess I'm not going to discuss which shale it is or what part of our acreage. And we'll be at least getting some vertical information and maybe a core in that other shale within the next six to 12 months and possibly drilling a horizontal in it within the next year to year and a half.

Great. Thanks very much.

(Operator Instructions) There are no more questions in the queue and I would now like to turn the call over back to Mr. Tim Silverstein for closing remarks.

Thank you, Madge. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2 PM Eastern Time on both our website and by telephone, and will run through the close of business on Friday, May 14, 2010. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone call 1-888-286-8010 and enter passcode 94473740. This concludes our conference call for today. Thank you and good-bye.

Thank you for participation in today's conference. This concludes the presentation and you may now disconnect. Good day.